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California is conducting what may be the most ambitious electricity customer empowerment experiment ever done anywhere; whether it will work remains very much in doubt.

The state is the national leader in both utility-scale solar and distributed solar capacities and fourth in the nation in wind capacity. Yet California’s dominant investor-owned utilities (IOUs) procured zero new MW of renewable energy capacity in 2017. And a preliminary plan released in January by state regulators proposes almost no 2018 procurement.

But the failure of procurement is just the symptom. The problem is widespread power sector uncertainty causing what one key observer called an “upheaval.” The disruption does not support California’s goals to cut its greenhouse gas emissions 40% below 1990 levels by 2030 and achieve its 50% renewable energy by 2030 mandate. And it threatens the stability of utility-scale renewable energy builders.

Efforts to resolve the problem have, however, been stymied because the state's regulators and factions representing utility-scale renewable energy developers are sharply at odds over its urgency.

Causes of upheaval

California’s successful transition to renewables is one cause of the current upheaval. It has left the state with midday solar overgeneration and a sharp, difficult to manage demand spike in the late afternoon and evening.

Another source of upheaval is the Pacific Gas and Electric (PG&E) decision to shutter the state’s last nuclear power plant, Diablo Canyon, by 2025. It raises the contentious question of how the state should fill the 2,200 MW deficit of emissions-free baseload generation. Because of its peak demand spike, the state needs flexible generation, but natural gas peakers will make the climate goals harder to reach.

The California Public Utilities Commission (CPUC) recently closed its Diablo Canyon proceeding without guidance on a solution. Renewable energy advocates say failing to act before 2019 could mean wind and solar developers will miss out on valuable federal tax credits, resulting in hundreds of millions of dollars in higher project costs being passed to electricity customers.

The third and biggest cause of upheaval is the rise of community choice aggregation (CCA). A 2002 law allows CCAs to act as load serving entities (LSEs) and take on IOU customers. Active CCAs now serve 660,000 California electricity customers. And cities and counties with populations totaling more than 15 million people are considering the move, according to the CPUC.

San Diego’s mayor must decide whether the city’s 100% renewable energy by 2035 goal will be met by San Diego Gas and Electric (SDG&E) or the city’s new CCA. Yet the mayor is delaying his decision until technical questions that will determine CCAs' cost of power, unresolved by the CCA law, are settled by the CPUC later this year. Minimal renewable energy procurement from any IOUs or CCAs is expected until these financial questions are resolved.

Renewable energy advocates say the CPUC has failed to lead. Some want a new form of regulation for CCAs. CCA advocates say they will be regulated only by their own boards. CPUC President Michael Picker told Utility Dive his agency is doing what regulators must do to protect ratepayers during times of upheaval.

Accelerated procurement

“The market is currently rife with uncertainty due to customer load migration, potential cost-shifting, and regulatory/jurisdictional ambiguity," their letter, not made public but shared with Utility Dive, argued.

CCAs Marin Clean Energy, Lancaster Choice Energy, Sonoma Clean Power and Peninsula Clean Energy have a total of nine wind and solar contracts. Between 2018 and 2021, they expect to add 768 MW of new wind and solar capacity to the 2.4 GW built by the state’s IOUs.

But the CPUC is not using its authority to drive new procurement, Nancy Rader, executive director of the California Wind Energy Association, emailed Utility Dive. It needs to act to prevent utility customers from "missing out" on savings of as much as "$444 million annually" that would come from procuring for post-2020 electricity needs before the federal tax credits for wind and solar expire. Rader was one of the signatories of the letter to Brown.

Other signers of the letter see the threat to the renewable energy industries they represent as so disruptive that they would speak to Utility Dive only on background.

Ed Smelof, regulatory issues managing director for the Vote Solar advocacy group, said that just filling the gap left by the Diablo Canyon closure is another important reason renewable energy procurement should be accelerated.

The commission's preliminary IRP ruling leaves a gap in procurement, but it “is a non-binding blueprint” and will lead to a more complete assessment of the state’s needs, she added.

Consequences of success

CPUC President Michael Picker said the state is “dealing with the consequences of success.” Though the procurement slowdown is hard on some developers, the commission’s job is not “economic development,” he said. “It is to meet state electricity needs, and the closure of Diablo Canyon in seven years does not create a present need.”

Arguments for new development are “naked self-aggrandizing and self-pleading,” he insisted. “We concluded the projections of hundreds of millions of dollars of savings from accelerated procurement are no longer accurate.”

The commission is “not persuaded of the need to order near-term procurement,” according to its preliminary ruling (rulemaking 16-02-007). Modeling showed that without the federal tax credits, only 250 MW less renewable energy capacity would be procured. And the newly-imposed solar tariffs could act as a counterbalance to price.

In addition, “renewable costs have been declining for many years, and likely will continue to do so,” the ruling reported. Buying now could “lock in higher-than-necessary prices.”

Requiring near-term purchases by utilities would also complicate the transition from IOUs to CCAs, the commission decided. IOUs may not need more, if predictions of the "departing load” are fulfilled.

The power charge indifference adjustment

That “departing load” potential was a major factor in the CPUC’s decisions in the IRP and Diablo Canyon proceedings, stakeholders agreed.

Procurement imposed on IOUs that is ultimately transferred to CCAs would require “a likely-unpopular cost allocation methodology to ensure that the costs are shared by the benefiting customers,” the ruling concluded.

That concern cannot be resolved until the commission reaches its decision on the Power Charge Indifference Adjustment (PCIA). The PCIA is used to allocate to CCAs the costs incurred by IOUs for generation to serve customers who depart to CCAs. It is based on the generation’s estimated future market value and fluctuates with changing market prices.

Southern California Edison (SCE), PG&E and SDG&E submitted a Joint Utilities filing to the CPUC proposing a new mechanism based on actual, rather than estimated, costs.

The San Diego Mayor's office told Utility Dive the mayor will not choose between San Diego Clean Choice Energy, the CCA, and the SDG&E proposal until the ongoing CPUC proceeding is completed later this year. Until the value of that charge is decided, it will not be clear whether the San Diego Clean Choice Energy or SDG&E offering is the best deal

Other CCA-imposed challenges

Cost allocation is only one of the CCA-related uncertainties slowing renewable energy procurement by IOUs and CCAs.

“The CCAs also argue the commission has no authority over them and their planning is only subject to the approval of their local Boards,” Smeloff said. “It could wind up in the courts because it is a question of the legal difference between CPUC 'certification' and CPUC 'approval' of CCA planning.”

This uncertainty only adds to inclinations by regulators and utilities to avoid moving forward.

California Wind Energy Association’s Rader said another uncertainty impacting procurement is that CCAs’ financial backing leaves their creditworthiness in doubt.

The alliance represents a potential 2.4 million customers in unincorporated Los Angeles County municipalities. It began serving its first 2,000 accounts in February, spokesperson Gary Gero told Utility Dive.

It will offer customers the choice of 36% renewables, 50% renewables or 100% renewables, Gero said. Though its rates now include the PCIA, they are 2% below SCE rates. Its initial procurement is through short-term contracts and it is completing a deal with SCE to obtain its state mandated Resource Adequacy obligation.

The Clean Power Alliance of Southern California will be creditworthy, he added. Responses by major financial institutions to its solicitation for banking and credit services show “the willingness of the financial community to extend backing, based on our billion-dollar annual revenues."

Gero believes most complaints about CCAs are the result of misunderstanding. “We fully intend to build and pay for new renewable power facilities, but we can’t do that on day one,” he said. “We will meet state laws, including renewables mandates and resource adequacy requirements.”

But CCAs will not allow the state to direct or guide their procurement because local engagement and choice is fundamental to the CCA identity, Gero said. And statewide coordination of CCA procurement is not necessary because sound business practices and rules now in place will produce a diversified resource mix and a stable grid.

“Nobody wants to break the state power system and it is not in our interest to let that happen,” he added. “If the state identifies a system issue, we will be the first to step up and do what we are asked to do to avoid it.”

The original CCA legislation may need reconsideration because it has had unintended consequences, he said. It did not envision them becoming a statewide avenue for climate activism at the local level. And state level oversight that CCAs accept could allow the state to help with some of their startup challenges.

State backing of their financing and coordination of their procurement could help them build more balanced and cost-effective portfolios, he suggested.

UCS’s Wisland said it is too soon to conclude commission oversight has not worked because uncertainties could be resolved in ongoing commission proceedings.

Former CPUC staffer Matthew Tisdale, now executive director for California think tank Gridworks, said CCA obligations to compensate the IOUs for departing load and to cooperate with state regulators will soon be formally clarified. That will resolve this “transitional upheaval” and restart procurement, he said. Until then, “it is prudent for the commission to be cautious.”

If the commission had ordered accelerated renewable energy procurement, it would have built more cost into utility portfolios, he said. “That would make finding an equitable PCIA resolution more difficult.”

CPUC President Picker said CCAs vary widely, but all will soon be required to meet a significant portion of their customer load through long term contracts, which would demonstrate which are financially viable and willing to recognize some CPUC authority.

“Some, but not all, will meet that obligation,” Picker said. “We need to think about what that means to the state's overall procurement goals.”

Not all CCAs oppose regulation, he added. Some, like the Clean Power Alliance of Southern California, have begun to work with IOUs to meet resource adequacy obligations. Some remember California’s energy crisis and “don't want to be responsible for crashing the grid,” he said. “But the naivete of others scares me.”

Given the uncertainty, “it's probably better not to rush into more investment,” he said. “There is significant risk in acting and no great risk in waiting.”

Gridworks’ Tisdale added that the “real story” is that “the most progressive regulatory commission in the world decided the state has enough renewables to take a minute and understand how the system is developing before it turns any more cranks.”